The present invention relates to diagnostics of electrical components. More specifically, the present invention relates to a partial discharge detection system for detecting a partial discharge in such electrical components.
High voltage electrical components such as those used in power distribution and switching, use dielectric materials or other insulators to provide electrical insulation. In some instances, the insulator can completely fail leading to a discharge path through the electrical insulator. However, in other instances, a partial discharge or arc or flashover may occur through only a small portion of the insulator. Such an event does not typically immediately result in a complete failure of the electrical insulator but does lead to degradation of the component and may eventually lead to a complete failure.
Dielectrics (insulators) are specified to have a breakdown voltage well above the operational requirements to provide a margin of safety against localized defects and aging. Recently manufactured assets for medium and high voltage are typically tested for defects and weak spots at commissioning; however numerous aging assets have insulators of unknown quality. Furthermore, as insulators age, weak spots become weaker and defects evolve and expand. Under certain load conditions a dielectric breakdown will initiate across the defect, causing a partial arc between the conductors at different potentials and/or within cracks and voids within the dieletric.
As opposed to a complete flashover, the partial discharge does not provide a high current path between conductors. The localized fault is confined to the defect and the fault current is limited by the capacitive reactance of the remainder of the insulator thickness in series with the defect. Such defects can happen along the surface of an insulator (e.g. tracking faults) or internal to a solid insulator. A more common class of surface discharge occurs near a metal-air boundary at sharp edges. Electrons emitted from the sharp edge ionize the air, causing a corona discharge.
In any case, the breakdown of the defect causes a small, but sudden, rise in current ranging from a few milliamperes to a few Amperes lasting for about a nanosecond. The result is a sudden discharge ranging from a few picocoulombs to tens of nanocoulombs. A distressed insulator could have as few as a single defect to an arbitrarily large number of defects. Where multiple defects exist, they will typically occur at unique breakdown voltages, therefor being distributed over time or phase of the line voltage.
Since the discharge is limited in intensity and confined to a defect, it is not an immediate threat to the health of the asset. However, the collapse of an electric potential through a current spike represents a highly localized dissipation of electric power. While the electric potential that collapses is a fraction of the system working voltage, it ranges from several hundred to several thousand volts and represents an instantaneous power ranging from a few Watts to a few kilowatts.
While the energy losses are not an operational concern at such low levels and time durations, the results can be problematic. Even though the total energy losses are small because of the short duration; each discharge causes additional stress to the defect, which worsens over time.
Partial discharge can be recognized by any of a number of consequences and symptoms. The discharges cause voltage or current spikes that travel along the conductors until they are dissipated—either through conductive losses, reactive dispersion, or electromagnetic radiation of energy as ultra high frequency (UHF) and very high frequency (VHF) emissions. The ultimate fate of these pulses depends greatly on the nature of the defect location. Pulses are known to travel kilometers along shielded cable since the conductor losses are low and the shielding reduces electromagnetic radiation. The most significant influence of such propagation is that the cables are low loss transmission line filters and, with increasing distance, the detectable energy is concentrated at low frequencies. If the pulses are not completely radiated or dissipated, they eventually terminate to earth as transient earth voltage (TEV) faults.
In other assets the situation is different and radiative losses are more likely. The discharges therefore often cause electromagnetic emissions at the point of discharge that can interfere with radio communications nearby if the defect is in an outdoor asset. The interference with AM radios was one of the first symptoms used to detect and identify partial discharge. Energy is also dissipated as ultraviolet and acoustic emissions if the defects are sufficiently close to an air boundary.
In addition to the energy emissions (radio waves, ultrasound, and optical) that occur during a discharge, there are visual indications of past discharges including pitted damage to conductors, deformation and discoloration of insulators from the localized heating, and deposition of oxidized material as a fine white powder.
The use of AM radios to detect the interference is a classic technique; however early versions of this method were not quantitative nor were they able to verify that the source of interference was from partial discharge as opposed to corona or conducted interference from radio equipment being radiated from connected equipment.
One of the most reliable methods for detection and analysis of partial discharge is the direct observation of the current and voltage spikes. The sudden discharge is always associated with a localized change in current with an average impulse current equal to the discharge divided by the duration of the event. Since all electrical systems have finite transmission line impedance, the current spike has a corresponding voltage spike. Using a high voltage capacitive coupler to sample the voltage pulse or a high frequency current transformer to sample the current pulse gives a nearly direct picture of the discharge. There is still some variability in the detectable pulses at accessible locations in the asset depending on the location of the defect; however this variability is generally believed to be smaller than for other methods of detection and most analytical equipment uses this method. IEC60270 accounts for this uncertainty by referring to the calibrated scale as apparent charge. That is, it is the measured or “apparent” charge response that correlates to a reference charge injected to the equipment at a reference location. Real discharges occurring at locations other than the reference location might deviate from the reference value, and thus the apparent value, but are quantified by their apparent magnitude.
The measurement of apparent charge has several strengths, including an ability to analyze the pulse shape of each pulse and the ability to assemble a graph of the discharge events relative to the phase of the power line waveform, called phase-resolved partial discharge (PRPD).
Advanced methods add numerical analysis of the pulse shape of individual pulses to discern valid discharges from other sources of current and voltage spikes. Systems using multiple detectors can employ time of flight analysis to locate the defect.
The direct observation has significant drawbacks. The foremost is expense. While the cost of failures in the electric grid almost always outweighs the cost of prevention, analytical instruments are still too expensive to be deployed as ubiquitous, early warning systems.
Furthermore, while the detailed information is critical to determining the location and root cause of discharges, there is simply too much information for ubiquitous deployment and the SCADA (Supervisory Control and Data Acquisition) requirements would be overwhelming. Finally, the coupling detectors are contact methods of measurement. While they are designed for safe operation at the rated voltages, dust, humidity, and breakdown of the nearby insulators can impair their safety over time. As permanent, early warning systems these solutions have been historically limited to extremely high value generation and transmission assets with less widespread deployment down the distribution network, where they are typically deployed after a problem is suspected.
Indirect analytical instruments measure surface transients on grounding material (transient earth voltage, TEV), high frequency current transformer (HFCT) signals, or radiated energy detected to baseband to obtain a signature of the original pulses. While indirect methods inherently lose some of the analytical information on the pulse signature, the time of flight and phase-resolved timing of the direct methods are retained. So is the overwhelming burden of data.
The indirect analytical instruments eliminate the safety concern by offering noncontact operation and are also capable of temporary installation onto live systems. The systems can also be somewhat lower cost, although typically with reduced analytical capability. Their additional drawback is a loss of calibration. The transduction of a discharge to the indirect parameter (TEV, VHF, UHF, acoustic, and optical) is not able to be quantitatively predicted so the systems are calibrated to an external stimulus and relative measurements of partial discharge are made.
The direct and indirect methods above are all time domain analytical methods using broadband analysis of individual pulses.
Another class of detection uses narrowband (frequency domain) analysis based on power spectral density of the emitted energy. These methods can be used with direct or indirect coupling and are especially common in UHF analysis. There can be several problems in acquiring such a frequency spectrum because the source signal can be transient while common spectrum analyzers sweep a narrow-band detector through a range of frequencies. Unless the discharge is present at that point of time in the sweep process, a discharge signal might be missed. Despite this, narrowband methods are believed to be a powerful method of scanning a site for sources of partial discharge and of characterizing such discharges.
These techniques sacrifice time/phase information in exchange for a somewhat simpler and safer measurement method. Even so, narrowband methods still suffer from an excess of data and difficulty of analysis by laypersons. There is an unmet need for an early warning monitor that is capable of distilling the complex data of either broadband or narrowband detection into concise, trendable data.